High flow rate multi array stimulation system

ABSTRACT

A system of sliding valves wherein the inserts of multiple sliding valves may be shifted to an open position using a single shifting ball. Each individual sliding valve has a movable insert that, depending upon the position of the insert within the sliding valve, may either block, permit fluid to radially flow between the interior and exterior of the sliding valve at a first rate, or permit fluid to radially flow between the interior and exterior of the sliding valve at some different second rate.

CROSS-REFERENCE TO RELATED APPLICATION

This is a non-provisional application which claims priority toprovisional application 61/525,525, filed Aug. 19, 2011, the contents ofthis application is incorporated herein by reference.

BACKGROUND

A common practice in producing hydrocarbons is to fracture thehydrocarbon bearing formation. Fracturing the hydrocarbon bearingformation increases the overall permeability of the formation andthereby increases hydrocarbon production from the zone fractured.Increasingly a single wellbore may intersect multiple hydrocarbonbearing formations. In these instances each hydrocarbon bearing zone maybe isolated from any other and the fracturing operation proceedssequentially through each zone.

In order to treat each zone sequentially a fracturing assembly isinstalled in the wellbore. The fracturing assembly typically includes ofa tubular string extending generally to the surface, a wellboreisolation valve at the bottom of the string, various sliding sleevesplaced at particular intervals along the string, open hole packersspaced along the string to isolate the wellbore into zones, and a topliner packer.

The fracturing assembly is typically run into the hole with the slidingsleeves closed and the wellbore isolation valve open. In order to openthe sliding sleeves a setting ball, dart, or other type of plug isdeployed into the string. For the purposes of the present disclosure aball may be a ball, dart, or any other acceptable device to form a sealwith a seat.

SUMMARY

The sliding sleeve has a movable insert that blocks radial fluid flowthrough the sliding sleeve when the sliding sleeve is closed. Fixed tothe insert is a releasable seat that is supported about the seatsperiphery by the internal diameter of the housing. Upon reaching thefirst releasable seat the ball can form a seal. The surface fracturingpumps may then apply fluid pressure against the now seated ball and thecorresponding releasable seat to shift open the sliding sleevepermanently locking it open. As the sliding sleeve and its correspondingseat shift downward the seat reaches an area where the releasable seatis no longer supported by the interior diameter of the housing causingthe releasable seat to release the ball. The ball then continues down toseat in the next sliding sleeve and the process is repeated until all ofthe sliding sleeves that can be actuated by the particular ball areshifted to a permanently open position and the ball comes to rest in aball seat that will not release it thus sealing the wellbore.

Once the lower wellbore is effectively sealed by the seated shiftingball and the sliding sleeves are open, the surface fracturing pumps mayincrease the pressure and fracture the hydrocarbon bearing formationadjacent to the sliding sleeves providing multiple fracturing initiationpoints in a single stage.

Because current technology allows multiple sliding sleeves to be shiftedby a single ball size multiple hydrocarbon bearing zones may befractured in stages where the lower set of sliding sleeves utilizes asmall diameter setting ball and seat and successively higher zonesutilize successively greater diameter setting ball and seat sizes.

A cluster of sliding sleeves may be deployed on a tubing string in awellbore. Each sliding sleeve has an inner sleeve or insert movable froma closed condition to multiple opened or partially opened conditions.When the insert is in the closed condition, the insert preventscommunication between a bore and a port in the sleeve's housing. To openthe sliding sleeve, a ball is dropped into the wellbore and pumped tothe first sliding sleeve where it forms a seal with the releasable seat.Keys or dogs of the insert's seat extend into the bore and engage thedropped ball, providing a seat to allow the insert to be moved open withapplied fluid pressure. After opening, the external diameter of thehousing is in fluid communication with the interior portion of thehousing through the ports in the housing.

When the insert reaches its open position the keys retract from the boreand allow the ball to pass through the seat to another sliding sleevedeployed in the wellbore. This other sliding sleeve can be a clustersleeve that opens with the same ball and allows the ball to pass throughafter opening. Eventually, however, the ball can reach an isolation toolor a single shot sliding sleeve further down the tubing string thatopens when the ball engages its seat but does not allow the ball to passthrough. Operators can deploy various arrangements of cluster andisolation sleeves for different sized balls to treat desired isolatedzones of a formation.

After the various sliding sleeves are actuated it is sometimes necessaryto run a milling tool through the wellbore to ensure that the innerdiameter of the tubular is optimized for the fluid flow of theparticular well. The mill out may include removing portions of slidingsleeve ball seats that are not releasable and any other debris that maybe left over from the fracturing process.

At some point during the life of the well it may become desirable tochange the flow characteristics of the fluids in the wellbore. Typicallyafter fracturing the first set of ports in the sliding sleeve do nothave sufficient area to maximize fluid flow through the wellbore to thesurface. The first set of ports becomes the flow restriction in thewell. In order to maximize the fluid flow it may be necessary to accessa second set of ports. The second set of ports may be configured to addtheir flow area to that of the first set of ports to achieve an at leastequal flow area to that of the tubular string.

It may be desirable to shut off flow through the first set of ports andhave all of the fluid flow through the second set of ports. In the casewhere all of the fluid flows through the second set of ports the portsmay be configured to match the flow area of the tubular string.

A typical configuration of a sliding sleeve has at least two slidingsleeves. Each sliding sleeve in turn typically having a housing havingan outer housing diameter, an inner housing diameter, a first portallowing fluid communication between the inner housing diameter and theouter housing diameter, and a second port longitudinally offset from thefirst port that allows fluid communication between the inner housingdiameter and the outer housing diameter. Each sliding sleeve also has aninsert typically located within the inner housing diameter. Each inserthas an outer insert diameter, an inner insert diameter, a releasableseat, and a shifting profile. Each insert is typically located in theinner housing diameter so that it has a first position within the innerhousing diameter where fluid flow through the at least first and secondports is blocked.

A shifting ball pumped down from the surface actuates the releasableseat to facilitate movement of the insert between a first position and asecond position wherein the insert allows fluid flow through the firstport; after the insert is moved from its first position to its secondposition the shifting ball is released.

A shifting tool may then be run into the wellbore on coiled tubing, awellbore tractor, or any other device that may supply the necessaryforce to actuate the insert from its second position to a thirdposition. The shifting tool may be operated from surface as when coiledtubing is used, it may be operated remotely such as by a wellboretractor on an electric or hydraulic line, or it may be operated by anyother remote means that can supply sufficient force to move the insertfrom one position to any other such as from the second open position tothe closed position or from the second open position to the first openposition.

The insert's third position allows fluid flow through at the secondport. As the insert is moved between the second and third positions thefirst and second ports may be arranged such that in the second positionfluid flow through the second port may be blocked and when the insert isin the third position fluid flow through the first port may be blocked.In some cases it may be desirable to allow fluid flow through both thefirst and second ports when the insert is in its third position.

The first port may consist of a series of ports in approximately thesame longitudinal position around the sliding sleeves' housing. Thesecond port is longitudinally offset from the first port but may alsoconsist of a series of ports in approximately the same longitudinalposition around the sliding sleeves' housing. The first port and thesecond port may not have the same cross-sectional area nor is itnecessary that each port within the first ports or second ports have thesame cross-sectional area.

An alternate configuration of a downhole well fluid system is aplurality of sliding sleeves having a central throughbore and attachedto tubing string that is run into a wellbore. Each of the slidingsleeves is typically actuated by a single ball pumped down the tubingstring. The sliding sleeves have a closed condition and at least twoopen conditions and each sliding sleeve is able to be actuated from aclosed condition to a first opened condition.

The closed condition prevents fluid from radially flowing between thecentral throughbore and the wellbore and the first opened conditionallowing radial fluid communication between the central throughbore andthe wellbore. Each of the sliding sleeves in the opened conditionallowing the single ball to pass therethrough.

Each of the sliding sleeves may be changed from a first opened conditionto a second opened condition. The second opened condition typicallypermitting increased fluid flow between the central throughbore and thewellbore than the first opened condition. The ports in the slidingsleeve may be arranged so that the sliding sleeve in the second opencondition blocks fluid flow through the first ports.

It may be advisable to arrange the ports such that fluid communicationbetween the central throughbore and the wellbore is greater in thesecond open condition than in the first open condition. However, in someinstance it may be necessary to arrange the ports in the sliding sleevessuch the second open condition allows fluid flow through both the firstports and the second ports. In some cases the sliding sleeve in thefirst open condition blocks radial fluid communication through thesecond ports.

A shifting tool may be run into the wellbore on coiled tubing, awellbore tractor, or any other device that may supply the necessaryforce to actuate a sliding sleeves from its second position to a thirdposition. The shifting tool may be operated from surface as when coiledtubing is used, it may be operated remotely such as by a wellboretractor on an electric or hydraulic line, or it may be operated by anyother remote means that can supply sufficient force to move the insertfrom one position to any other.

A wellbore fluid treatment method may include deploying at least twosliding sleeves on a tubing string in a wellbore, each of the slidingsleeves having a housing, an outer diameter, an inner diameter, acentral throughbore, a first port allowing radial fluid communicationbetween the central throughbore and the wellbore, a second portlongitudinally offset from the first port allowing radial fluidcommunication between the central throughbore and the wellbore, and aclosed condition preventing radial fluid communication between thecentral throughbore and the wellbore.

Typically a ball is pumped or dropped down the tubing string to changethe sliding sleeves from a closed condition to a first open conditionallowing access to the first port. The ball is then released from thesliding sleeve and in many cases actuates another lower sliding sleeve.

At some time after the shifting ball has been released from the slidingsleeve a shifting tool is run down the tubing string to change thesliding sleeve from the first open condition to a second open conditionallowing access to the second port. Depending upon the needs of theoperator changing between the first open condition and the second opencondition seals the first port or perhaps changing between the firstopen condition and the second open condition allows access to bothsecond port and the first port. Depending upon the wellbore conditionschanging between the first open condition and the second open conditionallows or restricts access to various ports and radial fluid flow mayincrease or decrease.

The foregoing summary is not intended to summarize every potentialembodiment of the present invention.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a schematic view of a fracturing assembly installed in awellbore.

FIG. 2 depicts a sliding sleeve with a releasable seat in the closedposition.

FIG. 3 depicts a sliding sleeve with a releasable seat in the openposition.

FIG. 4A depicts an array sliding sleeves using at least two differentsizes of ball prior to activation.

FIG. 4B depicts an array sliding sleeves using at least two differentsizes of ball during activation.

FIG. 5 depicts a high flow sliding sleeve with the ports closed.

FIG. 6 depicts a high flow sliding sleeve with the fracturing portsopen.

FIG. 7 depicts a sliding sleeve with a releasable seat in the openposition and having a shifting profile.

FIG. 8A depicts a shifting tool with the radially movable latch in theretracted position attached to coiled tubing.

FIG. 8B depicts a shifting tool with the radially movable latch in theextended position attached to coil tubing.

FIG. 8C depicts a shifting tool with the radially movable latch in theextended position attached to a wellbore tractor.

FIG. 9 depicts a high flow sliding sleeve with the high flow ports open.

FIG. 10 depicts a high flow sliding sleeve with the fracturing ports andthe high flow ports open.

DETAILED DESCRIPTION

The description that follows includes exemplary apparatus, methods,techniques, and instruction sequences that embody techniques of theinventive subject matter. However, it is understood that the describedembodiments may be practiced without these specific details.

FIG. 1 depicts a schematic view of a wellbore 11 with a single zone andhaving a fracturing assembly 10 therein. The fracturing assembly 10typically consists of a tubular string 12 extending to the surface 20,an open hole packer 14 near the upper end of the sliding sleeves 16, anda wellbore isolation valve 18. At the surface 20, the tubular string 12is connected to the fracturing pumps 30 through the rig 40. Thefracturing pumps 30 supply the necessary fluid pressure to activate thesliding sleeves 16. The open hole packer 14 at the upper end of thesliding sleeves 16 isolates the upper end of the formation zone 22 beingfractured. At the lower end of the sliding sleeves 16 a wellboreisolation valve 18 is placed to seal the lower end of the formation zone22 being fractured.

The fracturing assembly 10 may be assembled and run into the wellbore 11for a predetermined distance such that the wellbore isolation valve 18is past the end of the formation zone 22 to be fractured, the open holepacker 14 is above the formation zone 22, and the sliding sleeves 16 aredistributed in the appropriate places along the formation zone 22.Typically, when the fracturing assembly 10 is run into the wellbore 11each of the sliding sleeves 16 are closed, the wellbore isolation valve18 is open, and the open hole packer 14 is not set.

As depicted in FIG. 2, once the fracturing assembly 10 is properlylocated in the wellbore lithe operator pumps down a shifting ball, dart,or other type of plug 66 to shift open the desired sliding sleeves 16.Upon reaching the first appropriately sized releasable seat 52 the ball66 can form a seal.

The ball 66 forms a seal with seat 52 in sliding sleeve 16, where thesleeve is in a closed position with a type of releasable ball seat 52such as is used in WEATHERFORD'S MULTI ARRAY STIMULATION SYSTEM. FIG. 3depicts the sliding sleeve 16 in the open position and includes likereference numbers. As depicted in the cross-section of FIG. 3 depictedin FIG. 3AA, the sliding sleeve 16 has a housing 50, with an outerdiameter 51, an inner diameter 53 defining a longitudinal boretherethrough 54, and having ends 56 and 58 for coupling to the tubularstring 12. Ports 60 are formed in the housing 50 to allow fluidcommunication between the interior of the housing 50 and the exterior ofthe housing 50. Located about the interior of the housing 50 is an innersleeve or insert 62 having an outer insert diameter 61 and an innerhousing diameter 63 that is movable between an open position (see FIG.3) and a closed position (see FIG. 2). The insert 62 has slots 64 formedabout its circumference to accommodate the releasable seat 52. Thereleasable seat 52 is supported about its exterior diameter by the innerdiameter of the housing 50.

Conventionally, the operator uses the fracturing pumps 30 to force ashifting ball 66 down the wellbore 11. When the shifting ball 66 engagesand seats on the releasable seat 52 a seal is formed. The fluid pressureabove the shifting ball 66 is increased by the fracturing pumps 30causing the releasable seat 52 and its corresponding insert 62 to movetowards the bottom of the wellbore 11. As the insert 62 moves towardsthe bottom the wellbore ports 60 are uncovered allowing radial accessbetween the interior portion of the housing 50 or the housinglongitudinal bore 54 and the exterior portion of the housing 50accessing the formation zone 22. As the releasable seat 52 and insert 62move together, the releasable seat 52 reaches an at least partiallycircumferential slot 68 as depicted in the cross-section of FIG. 3depicted in FIG. 3BB. The at least partially circumferential slot 68 maybe located in the inner diameter of the housing 50 where typicallymaterial has been milled away to increase the inner diameter of thehousing 50. Before the shifting ball 66 actuates the sliding sleeve 16and thereby moving the releasable seat 52 and insert 62, the releasableseat 52 is supported by the inner diameter of the housing 55. As theouter diameter of the releasable seat 67 reaches the slot 68 thereleasable seat 52 recesses into the at least partially circumferentialslot 68. Typically, the releasable seat 52 recesses into the at leastpartially circumferential slot 68 because as the releasable seat 52 andinsert 62 move down, the releasable seat 52 is no longer supported bythe inner diameter of the housing 53 causing the outer diameter of thereleasable seat 67 to move into the at least partially circumferentialslot 68 and thereby causing a corresponding increase in the innerdiameter 65 of the releasable seat 52 thereby allowing the shifting ball66 to pass through the sliding sleeve 16.

Typically the sliding sleeves 16 are grouped together such that thosesliding sleeves 16 actuated by a particular shifting ball size arelocated sequentially near one another. However it is sometimes desirableto open the sliding sleeves in a non-sequential manner. For example suchas when interspersing at least three sliding sleeves actuated bydifferent shifting balls sizes. In these instances while several slidingsleeves in the wellbore 11 may be shifted by shifting balls of the samesize, these sliding sleeves do not have to be sequentially located nextto one another. For example as depicted in FIG. 4A sliding sleeves 120and 122 are located in a tubular string 124 and are actuated by the samesized shifting ball 128. In FIG. 4A sliding sleeves 120 and 122 areplaced above and below a third sliding sleeve 126 that is actuated by adifferent sized but larger shifting ball (not shown). The smallershifting ball 128 can then be pumped down the well where it lands on thefirst releasable seat 130 in sliding sleeve 120. As depicted in FIG. 4Bpressure from the fracturing pumps 30 (FIG. 1) against the shifting ball128 and the corresponding releasable seat 130 forces the insert 132 andthe first releasable seat 130 downwards until the releasable seatreaches the circumferential slot 134. The releasable seat 130 then movesoutwardly into the circumferential slot 134 thereby increasing the innerdiameter of the releasable seat 130 and releasing the shifting ball 128.The releasable seat 136 has a large enough diameter that shifting ball128 passes through sliding sleeve 126 without actuating sliding sleeve126. The shifting ball 128 will then land on the second releasable seat138 forcing the insert 140 and the second releasable seat 138 downwardsuntil the releasable seat reaches the circumferential slot 142. Thesecond releasable seat 138 then moves outwardly into the circumferentialslot 142 thereby increasing the inner diameter of the releasable seat138 and releasing the shifting ball 128.

After actuating the correspondingly sized sliding sleeves the shiftingball may then seat in the wellbore isolation tool 18 or actuate anyother tool to seal against the wellborel 1. Fluid is then diverted outthrough the ports 60 in the sliding sleeves 16 and into the annulus 24created between the tubular string 12 and the wellbore 11.

In order to isolate the formation zone 22 the open hole packer 14 andthe packer associated with the wellbore isolation valve 18 may be setabove and below the sliding sleeves 16 to isolate the formation zone 22and the portion of the sliding sleeves 16 from the rest of the wellbore.

The fracturing pumps 30 are now able to supply fracturing fluid at theproper pressure to fracture only that portion of the formation zone 22that has been isolated. After the formation 22 has been fractured anyhydrocarbons may be produced.

Typically the port 60 used during the fracturing process has a smallercross-sectional area than the tubular string 12. As any produced fluidstravel out of the formation zone 22 and into the tubular string 12 theport 60 becomes a flow restriction for the produced fluids. In order toovercome the potential flow restriction it may be advisable to place asecond set of flow ports around the sliding sleeve's housing.

FIG. 5 depicts a cross-sectional view of a sliding sleeve 200 having aport 60 and a second port 202 longitudinally offset from the port 60.When the sliding sleeve 200 is run into the wellbore 11 (FIG. 1) theinsert 210 is in the closed position where radial fluid flow throughport 60 and second port 202 is blocked.

FIG. 6 depicts a cross-sectional view of a sliding sleeve 200 having aport 60 and a second port 202 longitudinally offset from the port 60.After the sliding sleeve 200 is run into the well the shifting ball 66(FIG. 2) forms a seal with the releasable seat 52 (FIG. 2) to force theinsert 210 to move down against a lower stop 212. The exposing port 60and allowing radial fluid flow through port 60 between the interior andthe exterior of the sliding sleeve 200 and the shifting ball 66 (FIG. 2)is released. The operator is now able to fracture the formation zone 22(FIG. 1).

When the formation zone 22 (FIG. 1) is fractured small ports are desiredto maintain a high enough pressure profile through the relevantfracturing assembly 10 (FIG. 1) to ensure that the formation zone 22(FIG. 1) is fractured according to plan. After fracturing the formationzone 22 (FIG. 1) the operator can begin to produce the well. Becausetypically the port 60 has a smaller cross-sectional area that thetubular string 12 (FIG. 1) and fracturing assembly 10 (FIG. 1) includingthe sliding sleeve 200 and insert 210 port 60 is now a flow restrictionfor produced fluids. It is therefore desirable to have a simple means toincrease the total ability of the sliding sleeve to provide radial fluidflow between the exterior of the sliding sleeve and the interior of thesliding sleeve.

FIG. 7 depicts a sliding sleeve 70 with a type of releasable ball seat72 in the open position allowing fluid communication through the ports90 between the interior of the housing and the exterior of the housing.The sliding sleeve 70 has a housing 74 defining a longitudinal bore 76therethrough and having ends 78 and 80 for coupling to the tubingstring. Located about the interior of the housing is an inner sleeve orinsert 82 that is movable between an open position and a closedposition. The insert 82 has slots 84 formed about its circumference toaccommodate the releasable seat 72. The insert 82 has a profile 88formed about the inner insert diameter 91. The profile 88 is typicallyformed by circumferentially milling away a portion of material around atleast one end of the inner insert diameter 91. The releasable seat 72 issupported around the outer diameter of the releasable seat 72 by theinner diameter of the housing 74. A snap ring 93 is provided incircumferential slot 92 about the exterior diameter of insert 82. Thesnap ring 93 latches into circumferential slot 92 about the interiordiameter of the housing 74 to retain the insert 82 in an open position.As the insert 82 is moved between an open position and a closed positionthe snap ring 93 will retract into circumferential slot 92 until itreaches circumferential slot 94 about the interior diameter of thehousing where it will expand into circumferential slot 94 and therebyretaining the insert 82 in the closed position.

FIG. 8A depicts a shifting tool 100 having a radially movable latch 102Ato latch into profile 88. The shifting tool 100 may be run into thefracturing assembly 10 on coiled tubing 106, by a wellbore tractor, orby any other means that can carry the shifting tool 100 into thefracturing assembly 10. Typically the shifting tool may be run into thewellbore 11 with the movable latch in a radially retracted position 102Areducing the outer diameter of the shifting tool 100 and allowing theshifting tool 100 to clear any areas of reduced diameter inside of thefracturing assembly 10.

FIG. 8B depicts a shifting tool 100 with the radially movable latch 102Bin its extended position. Once the shifting tool 100 is located in theprofile 88 the movable latch is actuated from its radially retractedposition 102A to its radially extended position 102B and engages profile88 (FIG. 7) within the insert 82 (FIG. 7). Tension is then applied tomove the shifting tool 100 and thereby insert 82 from its open positionto its closed position to block fluid flow between the exterior of thehousing 74 through the ports 90 and into the interior of the housing.Typically the tension is applied from the rig 40 (FIG. 1) on the surfacehowever, as depicted in FIG. 8C any device such as an electrically(electric line 110) or hydraulically driven wellbore tractor 108 thatcan provide sufficient force to the shifting tool 100 to shift theinsert 82 may be used.

Once the insert 82 is moved to its closed position tension from thesurface on the shifting tool 100 is reduced. The movable latch on 102 onshifting tool 100 is moved from its extended position to its retractedposition thereby disengaging profile 88. The shifting tool may then bemoved to its next position to shift the insert on another tool or theshifting tool may be retrieved from the wellbore.

FIG. 9 depicts a cross-sectional view of a sliding sleeve 200 having aport 60 and a second port 202 longitudinally offset from the port 60.After fracturing the formation zone 22 (FIG. 1) the total radial fluidflow between the exterior of the sliding sleeve and the interior of thesliding sleeve may be increased by utilizing a shifting tool 100 (FIG.8A) to engage the shifting profile 88 (FIG. 7) to shift the insert 210upwards against the upper stop 214 thereby allowing radial fluid flowthrough second port 202. Typically second port has a largercross-sectional area than port 60. Each port 60 and second port 202 mayinclude multiple openings spaced circumferentially around the slidingsleeve. Depending upon the particular characteristics desired secondport 202 could have a larger, a smaller, or the same cross-sectionalarea as port 60. Also depending upon the particular characteristicsdesired the second port 202 and the port 60 can be opened together (asillustrated in FIG. 10)or in any order desired.

While the embodiments are described with reference to variousimplementations and exploitations, it will be understood that theseembodiments are illustrative and that the scope of the inventive subjectmatter is not limited to them. Many variations, modifications, additionsand improvements are possible. For example, the method of shifting theinsert between an open position and a closed position as describedherein is merely a single means of applying force to the sliding sleeveand any means of applying force to the sliding sleeve to move it betweenan open and a closed position may be utilized.

Plural instances may be provided for components, operations orstructures described herein as a single instance. In general, structuresand functionality presented as separate components in the exemplaryconfigurations may be implemented as a combined structure or component.Similarly, structures and functionality presented as a single componentmay be implemented as separate components. These and other variations,modifications, additions, and improvements may fall within the scope ofthe inventive subject matter.

What is claimed is:
 1. A downhole assembly comprising at least twosliding sleeves actuatable by a shifting ball and a shifting tool, eachsliding sleeve further comprising: a housing having an inner bore, afirst port allowing fluid communication with the inner bore, and asecond port allowing fluid communication with the inner bore, the secondport longitudinally offset from the first port; and an insert locatedwithin the inner bore of the housing and having a releasable seat,wherein the insert in a first position within the housing blocks fluidflow through the first and second ports; the releasable seat beingengagable by the shifting ball to move the insert from the firstposition to a second position, wherein the insert in the second positionallows fluid flow through the first port and blocks fluid flow throughthe second port, and wherein the releasable seat in the second positionreleases the shifting ball; and the insert being further engagable bythe shifting tool run into the slding sleeve to move the insert from thesecond position to a third position, wherein the insert in the thirdposition allows fluid flow through at least the second port; wherein thereleasable seat of each of the at least two sliding sleeves is engagableby the same shifting ball, and wherein the insert of each of the atleast two sliding sleeves is engagable by the same shifting tool.
 2. Thedownhole assembly of claim 1, wherein the insert in the third positionallows fluid flow through the first port and the second port.
 3. Thedownhole assembly of claim 1 wherein the cross-sectional area of thefirst port is less than the cross-sectional area of the housing.
 4. Thedownhole assembly of claim 1 wherein the combined cross-sectional areaof the first port and the second port is approximately equal to orgreater than the cross-sectional area of the housing.
 5. The downholeassembly of claim 1, wherein the shifting tool run into the slidingsleeve is moved by coiled tubing.
 6. The downhole assembly of claim 1,wherein the shifting tool run into the sliding sleeve is moved by awellbore tractor.
 7. The downhole assembly of claim 1, wherein theinsert comprises a shifting profile engaged by the shifting tool runinto the sliding sleeve and operated from the surface.
 8. A downholewell fluid system actuatable by a single ball, comprising: a pluralityof sliding sleeves having a central throughbore and disposed on a tubingstring deployable in a wellbore; each of the sliding sleeves having aninsert being actuatable by the single ball deployable down the tubingstring; each of the inserts in the sliding sleeves, actuated by thesingle ball, moving between a closed condition and a first openedcondition, the insert in the closed condition preventing fluidcommunication between the central throughbore and the wellbore, theinsert in the first opened condition permitting fluid communicationbetween the central throughbore and the wellbore; each of the inserts inthe sliding sleeves in the first opened condition allowing the singleball to pass therethrough; and each of the inserts in the slidingsleeves being further movable between the first opened condition and asecond opened condition, the second opened condition permittingincreased fluid communication between the central throughbore and thewellbore than the first opened condition; wherein the sliding sleevesare actuatable by a shifting tool run into the sliding sleeves; andwherein the run-in shifting tool engages the sliding sleeve to actuatethe sliding sleeves between the first opened condition and the secondopened condition.
 9. The downhole assembly of claim 8, wherein thesliding sleeve in the second open condition blocks fluid communicationthrough the first ports.
 10. The downhole assembly of claim 9, whereinfluid communication between the central throughbore and the wellbore isgreater in the second open condition than in the first open condition.11. The downhole assembly of claim 8, wherein the sliding sleeve in thesecond open condition allows fluid communication through one or morefirst ports.
 12. The downhole assembly of claim 8, wherein the slidingsleeve in the first open condition blocks fluid communication throughone or more second ports.
 13. The downhole assembly of claim 8, whereinthe shifting tool run, into the sliding sleeves is operated from thesurface.
 14. The downhole assembly of claim 8, wherein the shifting toolrun into the sliding sleeves is moved by coiled tubing.
 15. The downholeassembly of claim 8, wherein the shifting tool run into the slidingsleeves is moved by a wellbore tractor.
 16. The downhole assembly ofclaim 8, wherein the shifting tool run into the sliding sleeves isoperated remotely.
 17. A wellbore fluid treatment method, comprising:deploying at least two sliding sleeves on a tubing string in a wellbore,each of the sliding sleeves having a central throughbore, a first portallowing fluid communication between the central throughbore and thewellbore, a second port longitudinally offset from the first port andallowing fluid communication between the central throughbore and thewellbore, and an insert in a closed condition preventing radial fluidcommunication between the central throughbore and the wellbore; droppinga ball down the tubing string; using the ball to move the inserts ineach of the sliding sleeves between the closed condition and a firstopen condition allowing fluid communication through the first ports;releasing the ball from the sliding sleeves; running a shifting tooldown the tubing string into at least one of the sliding sleeves; andusing the run-in shifting tool to move the insert in the at least one ofthe sliding sleeves between the first open condition and a second opencondition allowing fluid communication through the second port.
 18. Themethod of claim 17 wherein moving the insert between the first opencondition and the second open condition seals the first port.
 19. Themethod of claim 17 wherein moving the insert between the first opencondition and the second open condition allows fluid communicationthrough both the second port and the first port.
 20. The method of claim19 wherein moving the insert between the first open condition and thesecond open condition increases fluid flow.